1. Field of the Disclosure
The present disclosure is generally directed to a downhole tool for use in oil and gas wells, and more specifically, to a coiled tubing bottom hole assembly with a packer and an anchor assembly for use in oil and gas wells containing solid-laden fluids. The packer and anchor assembly is particularly useful for isolating portions of a wellbore prior to fracturing oil and gas wells with coiled tubing.
2. Description of the Related Art
Perforating and fracturing operations have long been performed in completing oil and gas wells for production. Generally, perforating involves forming openings through the well casing and into the formation, by commonly known devices such as a perforating gun or sand jet. Thereafter, the perforated zone may be hydraulically isolated and fracturing operations are performed to increase the size of the initially-formed openings in the formation. Proppant materials are introduced into the enlarged openings in an effort to prevent the openings from closing.
More recently, techniques have been developed whereby perforating and fracturing operations are performed with a coiled tubing string. One such technique is known as the Annular Coil Tubing Fracturing Process, or the ACT-Frac Process for short, disclosed in U.S. Pat. Nos. 6,474,419, 6,394,184, 6,957,701, and 6,520,255, each of which is hereby incorporated by reference in its entirety. To practice the techniques described in the aforementioned patents, the work string, which includes a bottom hole assembly (BHA), must remain in the well bore during the fracturing operation(s). Performing proppant fracturing operations with coiled tubing presents many unique challenges.
One challenge of performing fracturing operations with coiled tubing is due to the small clearances between the BHA and the casing. Because of the small clearances, it is possible for the BHA to become wedged in the casing. Further, proppant used for fracturing may also lead to the BHA getting stuck within the wellbore. A stuck BHA poses significant problems to any perforating and fracturing operation because of the resulting lost time and expensive specialized machinery and operating crews needed to retrieve the BHA.
Another challenge of performing fracturing operations with coiled tubing may be attributable to the relatively low strength of the coiled tubing. As stated above, a BHA may have a propensity to get stuck within a casing. Because only limited pulling forces are available through coiled tubing, it might not be possible to pull a stuck BHA out using coiled tubing. Also the use of coiled tubing may present problems in setting the BHA within the wellbore. Typically in the prior art, a packer and anchor assembly is anchored in a casing by applying an axial mechanical force through the work string to the packer assembly. However, coiled tubing cannot be used to transmit large axial forces, so such anchoring operations may be less effective if axial forces through the work string are required. Because of the limited axial mechanical force that may be applied with coiled tubing, it may be preferred to use an anchoring system to anchor a coiled tubing BHA that may be actuated through the application of hydraulic pressure. Conventional pressure set anchor systems are typically button type anchors, which may not adequately secure the BHA while properly centering the packing element, as discussed below.
One particularly critical component in coiled tubing fracturing applications is the packer element of the BHA, which is employed to hydraulically isolate a portion of the wellbore. The packer assembly typically comprises some mechanism to seal against the interior of the casing such that one zone within the well may be isolated from another zone or zones, within the well. For example, during high pressure fracturing operations, it is necessary to isolate a target zone of the well such that the high pressure fracturing fluids may be introduced only into that zone of the well.
There are different types of sealing elements commonly employed in treating oil and gas wells. A first type is a squashable sealing element, for example the type used in compression set or tension set packers, wherein a seal element is deformed by an axial compressive force such that it sealingly engages the inside of the casing. One potential problem with the use of traditional compression set packers in coiled tubing applications is that, when such packers are employed, there is a very small radial clearance between the outside diameter of the packer assembly and the inside diameter of the casing. For example, for a casing with a 4 inch inside diameter, the unset outside diameter of the compression set packer is typically 3.771 inches. Such close clearance is ideal to minimize the extrusion gap between the packer assembly and the inside diameter of the casing. If compression set packers are intended for high pressure and temperature applications, permanently deformed back up rings can be used, however they further decrease the extrusion gap. The small radial clearance can present problems when trying to remove the BHA as discussed in detail below.
The use of proppants and/or cross linked gels in the fracturing fluid may increase the chance that the BHA becomes stuck in the wellbore due to the small clearances between the BHA and the casing. In addition, the sealing elements in such compression set packers do not readily return to their original shape or size, or do so at a slow rate. This further reduces the radial clearance between the packer assembly and the casing. The relatively small clearance required by squashable sealing elements makes them potentially problematic for coiled tubing fracturing applications, as the packer is more likely to become stuck in the well.
Additionally, squashable sealing elements generally require large forces to axially compress the sealing element to sealingly engage the casing. These large setting forces can be more easily attained with jointed pipe as compared to coiled tubing. Some strategies can be employed to enable the use of squashable set packers with coiled tubing; however, in some applications coiled tubing cannot be relied upon to generate the required forces to set the squashable sealing element. Therefore, because of the small clearances and large axial forces generally required to set a squashable sealing element, squashable sealing elements may not be acceptable for use in various coiled tubing applications.
Another broad category of packers are known as inflatable packers. In general, such packers have an inflatable member that is inflated to achieve the desired seal. Although such inflatable packers may have a relatively large clearance (e.g., 4″ ID casing, 3.125-3.5 OD packer), such inflatable packers may suffer from other potential problems.
One particular type of inflatable packer is a slat type packer that comprises an inner inflatable member, a plurality of metal slats and an outer cover member. In solid laden fluid or slurry applications, such slat type packers may get sand, proppant, and/or other solids in the various layers of the packer. When this occurs, the packer may not return to its original shape and size when it is deflated, or it may take a longer time to return to its original size and shape.
Another type of inflatable packer is generally known as a cord-type packer. This type of packer employs a unitary body comprised of an inner tube member, a plurality of cords for mechanical strength, and an outer cover. Although penetration of sand, proppant or other solids is not a concern with this type of an inflatable packer, a cord-type packer typically does not exhibit good recovery of its original shape in all applications. Complete recovery of the inflatable elements of inflatable packers is a problem in general, particularly when such packers are subjected to repeated use under elevated temperatures and pressures typically experienced in a well. Such lack of complete recovery may increase the chances of the tool getting stuck in the well.
One shortcoming of both squashable and inflatable type sealing elements is the inability to return to their original diameter after multiple sets. The rubber sealing element, after unsetting, retains a larger outer diameter than it had prior to expansion, resulting in a greater chance that the BHA may become stuck in the casing. In addition, these packers do not revert back to their original size and shape immediately or even rapidly. It is a common practice in the industry to wait several minutes, for example 15 minutes, after unsetting a rubber seal element in the BHA before attempting to move the BHA, to allow enough time for the rubber sealing element to pull away from the casing inner surface and revert to a smaller size to reduce the chance that the BHA will become stuck. This waiting period reduces the overall productivity of perforating and fracturing operations.
The anchor assembly is a component of a BHA used in the ACT-Frac Process. During the fracturing process, the large pressure differential on the set packer exerts a large force on the set anchor assembly. The anchor assembly when set is designed to be able to withstand this large force and retain the BHA at the set location during the ACT-Frac Process. Anchor assemblies are often set using large axial forces to move slips up a set of cones force the slips radially out to bite into and set the assembly against the casing. The setting of slips on corresponding cones may be helpful to center the BHA within the casing, which is important to ensure a uniform extrusion gap, as discussed herein. A large axial force may be needed to adequately set the slips against the casing. As discussed above, the ACT-Frac Process employs coiled tubing, which has a relatively low strength limiting the axial force that may be used to set slips of the anchor assembly. Thus, it would be beneficial to provide an anchor assembly that sets centers and adequately sets a BHA within a casing without the need of a large axial force.
In general, any packer assembly of a coiled tubing BHA is subject to inherent weaknesses of the coiled tubing. That is, coiled tubing cannot transmit large amounts of axial forces to the packer and anchor assembly, and cannot be used to rotate the BHA relative to the casing. In addition, the number of instances coiled tubing can be used to transmit forces at a determined depth is limited due to its low cycle fatigue life. Thus, it is desirable to reduce the likelihood that the packer assembly will cause the BHA to become stuck within the wellbore. Further, it may be beneficial to minimize the application of axial load to set the packer and/or the anchor. It would also be beneficial to provide a packer assembly for a BHA that had sufficient wellbore clearance in the unset state and that may be repeatedly set and unset with the packer rapidly returning close to its unset diameter providing sufficient wellbore clearance.
The present disclosure is directed to an apparatus for solving, or at least reducing the effects of, some or all of the aforementioned problems.